When drilling or completing wells in earth formations, various fluids typically are used in the well for a variety of reasons. Common uses for well fluids include lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroliferous formation), transportation of “cuttings” (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, transmitting hydraulic horsepower to the drill bit, emplacing a packer, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
In general, drilling and completion fluids should be pumpable under pressure down through strings of drill pipe, then through and around the drill bit head deep in the earth, and then back to the surface through an annulus between the outside of the drill stem and the hole wall or casing. Beyond providing drilling lubrication and efficiency, and retarding wear, drilling fluids should suspend and transport solid particles, drill cuttings, to the surface for screening and disposal. In addition, the fluids should be capable of suspending additive weighting agents (to increase specific gravity of the fluid), generally finely ground barites (barium sulfate ore), and transport clay and other substances capable of adhering to and coating the borehole surface.
Drilling and completion fluids are generally characterized as thixotropic fluid systems. That is, they exhibit low viscosity when sheared, such as when in circulation (as occurs during pumping or contact with the moving drilling bit). However, when the shearing action is halted, the fluid should be capable of suspending the solids it may contain, to prevent gravity separation. In addition, when the drilling fluid is under shear conditions and a free-flowing near-liquid, it must retain a sufficiently high enough viscosity to carry all unwanted particulate matter from the bottom of the well bore to the surface. The drilling fluid formulation should also allow the cuttings and other unwanted particulate material to be removed or otherwise settle out from the liquid fraction, such as during screening.
There is an increasing need for drilling fluids having these rheological profiles that enable wells to be drilled more efficiently. Drilling and completion fluids having tailored rheological properties ensure that cuttings are removed from the wellbore as efficiently and effectively as possible to avoid the formation of cuttings beds in the well which can cause the drill string to become stuck, among other issues. There is also the need from a drilling fluid hydraulics perspective (equivalent circulating density) to reduce the pressure required to circulate the fluid, helping to avoid exposing the formation to excessive forces that can fracture the formation causing the fluid, and possibly the well, to be lost In addition, an enhanced profile is necessary to prevent settlement or sag of the weighting agent in the fluid, because if this occurs, it can lead to an uneven density profile within the circulating fluid system, possibly resulting in loss of well control (gas/fluid influx) and wellbore stability problems (caving/fractures).
To obtain the fluid characteristics required to meet these challenges, the fluid must be easy to pump, so it requires the minimum amount of pressure to force it through restrictions in the circulating fluid system, such as bit nozzles or down-hole tools. In other words, the fluid must have the lowest possible viscosity under high shear conditions. Conversely, in zones of the well where the area for fluid flow is large and the velocity of the fluid is slow or where there are low shear conditions, the viscosity of the fluid needs to be as high as possible in order to suspend and transport the drilled cuttings. This also applies to the periods when the fluid is left static in the hole, where both cuttings and weighting materials need to be kept suspended to prevent settlement. However, it should also be noted that the viscosity of the fluid should not continue to increase under static conditions to unacceptable levels. Otherwise, when the fluid needs to be circulated again, this can lead to excessive pressures that can fracture the formation or, alternatively, can lead to lost time if the force required to regain a fully circulating fluid system is beyond the limits of the pumps.
Wellbore fluids must also contribute to the stability of the well bore, and control the flow of gas, oil, or water from the pores of the formation in order to prevent, for example, the flow or blow out of formation fluids or the collapse of pressured earth formations. The column of fluid in the hole exerts a hydrostatic pressure proportional to the depth of the hole and the density of the fluid. High-pressure formations may require a fluid with a specific gravity as high as 3.0.
A variety of materials are presently used to increase the density of wellbore fluids. These include dissolved salts such as sodium chloride, calcium chloride, and calcium bromide. Alternatively, powdered minerals such as barite, calcite, dolomite, ilmenite, siderite, hausmannite (manganese tetroxide), hematite and other iron ores, and olivine are added to a fluid to form a suspension of increased density. The use of finely divided metal, such as iron, as a weight material in a drilling fluid, where the weight material includes iron/steel ball-shaped particles having a diameter less than 250 microns and preferentially between 15 and 75 microns has also been described.
One requirement of these wellbore fluid additives is that they form a stable suspension and do not readily settle out. A second requirement is that the suspension exhibits a low viscosity in order to facilitate pumping and to minimize the generation of high pressures. Finally, the wellbore fluid slurry should also exhibit low fluid loss.
Conventional weighting agents such as powdered barite exhibit an average particle diameter (d50) in the range of 10-30 microns. A gellant, such as bentonite for water-based fluids or organically modified bentonite for oil-based fluids, is required to adequately suspend these materials. A soluble polymer viscosifier such as xanthan gum may be also added to slow the sedimentation rate of the weighting agent. However, as more gellant is added to increase the suspension stability, the fluid viscosity (plastic viscosity and/or yield point) increases undesirably, resulting in reduced pumpability. This is also the case if a viscosifier is used to maintain a desirable level of solids suspension.
The sedimentation (or “sag”) of particulate weighting agents becomes more critical in well bores drilled at high angles from the vertical, in that a sag of, for example, one inch (2.54 cm) can result in a continuous column of reduced-density fluid along the upper portion of the wellbore wall. Such high angle wells are frequently drilled over large distances in order to access, for example, remote portions of an oil reservoir. In such instances, it is important to minimize the plastic viscosity of a drilling fluid in order to reduce the pressure losses over the borehole length. At the same time, a high density should also be maintained to prevent a blow out. Further, as noted above, with particulate weighting materials, the issue of sag becomes increasingly important to avoid differential sticking or the settling out of the particulate weighting agents on the low side of the wellbore.
Being able to formulate a drilling or completion fluid having a high density and a low plastic viscosity is also important in deep, high pressure wells where high-density wellbore fluids are required. High viscosities can result in an increase in pressure at the bottom of the hole under pumping conditions. This increase in “Equivalent Circulating Density” (ECD) can result in the opening of fractures in the formation and serious losses of the wellbore fluid into the fractured formation. Again, the stability of the suspension is important in order to maintain the hydrostatic head to avoid a blow out.
After formulating a drilling fluid with desired rheological properties, one challenge during the drilling process is maintaining the properties of the drilling fluid during recycle and reuse. For example, as mentioned above, the drilling fluids transport solid particles, drilled solids, to the surface for screening and disposal. Recycling drilled solids into the wellbore is undesirable, as this can result in smaller sizes of drilled solids which can accumulate in the drilling fluid, ultimately affecting the properties of the drilling fluid. If the solids content increases, additional drilling fluid (water, oil, etc.) and other chemicals must be added to maintain the drilling fluid at its desired density, viscosity, and other physical and chemical properties for the drilling fluid to satisfy the requirements for drilling a wellbore. The drilling fluid and drill cuttings returned to the surface are often separated to maintain drilling fluid weight, thus avoiding costly dilution. The separated solids are then discarded or disposed of in an environmentally accepted manner.
Drill cuttings can originate from different geological strata, including clay, rock, limestone, sand, shale, underground salt mines, brine, water tables, and other formations encountered while drilling oil and gas wells. Cuttings originating from these varied formations can range in size from less than two microns to several hundred microns, including clays, silt, sand, and larger drill cuttings. Several types of separation equipment have been developed to efficiently separate the varied sizes of the weighting materials and drill cuttings from the drilling fluid, including shakers (shale, rig, screen), screen separators, centrifuges, hydrocyclones, desilters, desanders, mud cleaners, mud conditioners, dryers, filtration units, settling beds, sand traps, and the like. Centrifuges and like equipment can speed up the separation process by taking advantage of both size and density differences in the mixture being separated.
A typical process used for the separation of drill cuttings and other solids from drilling fluid is shown in FIG. 1, illustrating a stage-wise separation according to size classifications. Drilling fluid 2 returned from the well (not shown) and containing drill cuttings and other additives can be separated in a shale shaker 4, resulting in large particles 5, such as drill cuttings (greater than 500 microns for example), and effluent 6. The drilling fluid and remaining particles in effluent 6 can then be passed through a degasser 8, removing entrained gases; a desander 10, removing sand 15; a desilter 12, removing silt 16; and a centrifuge 14, removing even smaller particles 17. The solids 15, 16, 17 separated, including any weighting materials separated, are then discarded and the clean drilling fluid 18 can be recycled to the drilling fluid mixing system (not shown). Agitated tanks (not numbered) can be used between separation stages as holding/supply tanks.
The recovered, clean fluid can be recycled; however, the drilling fluid formulation must often be adjusted due to compounds lost during the drilling process and imperfect separation of drill cutting particles and other drilling fluid additives. As examples of imperfect separations, drilling fluid can be absorbed or retained with drill cuttings during separation; conversely, drill cuttings having a small size can remain with the drilling mud after separations. Losses during the drilling process can occur due to the mud forming a filter cake, and thus depositing drilling fluid additives on the wall of the wellbore.
Another example of losses includes the loss of drilling fluid additives with the separated drilled solids. It is well known to the drilling fluid industry that screen sizes of about 240 mesh (d100 of about 100 to 120 microns [API 13C]) will remove significant quantities of drilling grade barite (d90 of about 75 microns) together with drilled solids from a drilling fluid. Reconciling the requirement to dress shakers with sufficiently small aperture sized screens to remove unwanted drilled solids, without simultaneously removing valuable barite is difficult to achieve in practice. For example, U.S. Pat. No. 3,766,997, issued to Heilhecker et al., states that because the particle size of barite and low gravity solids overlap it is impossible to remove all the unwanted drilled solids.
Accordingly, there exists a need for a drilling fluid system, including various additives and separation equipment, where the drilling muds have desired rheological profiles, and where the characteristics of the drilling mud allow for improved solids separation efficiency.